The invention generally relates to a fluid level indication system and technique.
In oil fields it is typically important to know the levels of the fluids in the reservoir and around wells, and in particular, it may be important to know the depths of the interfaces between the gas, oil and water layers. Such knowledge is particularly important in secondary and tertiary recovery systems, for example, in steam flooding applications in heavy oil reservoirs.
Traditionally, the depths of the interfaces between the fluid levels are determined using pressure measurements. For example, one approach involves using a single pressure sensor, which makes a series of pressure measurements at multiple depths. The measured pressure is plotted against the depth. In each of the gas, oil and water layers, the pressure gradient is constant and proportional to the density of the fluid. The depths of the fluid layer interfaces, or boundaries, are identified by the intersections of the pressure gradient lines. The above-described technique of identifying the interface depths using a pressure sensor typically works well when carried out in an intervention in the well using, for example, a wireline-deployed tool.
For purposes of permanently monitoring the depths of the fluid interfaces, an array of pressure sensors may be placed across the gas, oil and water layers. In this regard, the pressure gradients may be plotted and the analysis that is set forth above may be applied. If the depths of the interfaces change over time, a large number of pressure sensors may be required to accurately assess the interface depths. A large number of pressure sensors may also be required if the initial positions of the interfaces are unknown or uncertain. However, several challenges may arise with the use of a large number of pressure sensors, such as challenges related to compensating the pressure readings for sensor offset and drift. Furthermore, the cost of an array of pressure sensors can be high and prohibitive.
Downhole distributed temperature sensing (DTS) involves the use of a sensor that indicates a temperature versus depth distribution in the downhole environment. DTS typically is used to identify and quantify production from different injection/production zones of a well.
For example, in a technique called “hot slug tracking,” DTS may be used to identify the permeable zones in a water injector well where injected fluid enters the formation. The permeable zones typically cannot be identified by DTS during normal injection. However, by shutting off injection and allowing the water in the tubing or casing above the injection zone to be heated up towards the geothermal gradient, a heated “slug” may be created. When the injection is re-started, the hot slug may be tracked versus time using the DTS measurements to identify the permeable zones.